Invert emulsion drilling fluids

ABSTRACT

A composition includes an oil phase; a water phase emulsified in the oil phase; a viscosifier including a carbon chain and a polar group disposed along the carbon chain; and a hydrophobic nanomaterial having an average particle size of less than about 1 μm. The hydrophobic nanomaterial including a silane or siloxane molecule having a nonpolar chain disposed on a surface thereof.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a divisional application of and claims the benefitof priority to U.S. patent application Ser. No. 15/480,035, filed onApr. 5, 2017, which claims priority to U.S. Provisional Application Ser.No. 62/319,112, filed on Apr. 6, 2016, the contents of which are herebyincorporated by reference.

BACKGROUND

Drilling fluids are used in oil and gas drilling to assist withlubricating the drill bit, ensuring well safety, forming filter cakes tominimize fluid loss into drilling formations, and transporting rockdebris to the surface of the well. Invert emulsion drilling fluids,which are emulsions of water in an oil or synthetic base phase, are usedin some drilling environments, such as in wells having features that mayreact to water-based drilling fluids or in high temperature or highpressure environments. Clays are sometimes added to invert emulsionfluids to act as viscosifiers and to stabilize the water-in-oil emulsionof the drilling fluid. In some instances, low gravity solids, such assmall calcium carbonate particles or clay-type materials, are added toinvert emulsion drilling fluids instead of clay to provide improvedthermal stability, resistance to high pressure, and tolerance tocontamination.

SUMMARY

In an aspect, a composition includes an oil phase; a water phaseemulsified in the oil phase; a viscosifier including a carbon chain anda polar group disposed along the carbon chain; and a hydrophobicnanomaterial having an average particle size of less than 1 μm. Thehydrophobic nanomaterial includes a silane or siloxane molecule having anonpolar chain disposed on a surface thereof.

Embodiments can include one or more of the following features.

The hydrophobic material forms a network. The network is continuousthroughout at least a portion of the composition. The compositionincludes a weighting material incorporated into the network formed bythe hydrophobic nanomaterial.

A sag factor of the composition is less than 0.53, such as between 0.50and 0.53.

The composition is substantially free of clay.

The composition is substantially free of low gravity solids having anaverage particle size of greater than 5 μm.

The viscosifier includes one or more of a fatty acid, a fatty amine, anda fatty ester.

The silane or siloxane molecule includes hexadecylsilane.

The hydrophobic nanomaterial includes hydrophobic nanosilica. Thehydrophobic nanosilica includes nanoparticles of silica having ahydrophobic outer surface.

The average particle size of the hydrophobic nanomaterial is less than500 nm, such as less than 100 nm, such as between 10 nm and 20 nm.

A yield point of the composition is greater than 10 lb/100 ft2, such as15 lb/100 ft2.

A plastic viscosity of the composition is less than or equal to 60 CP.

The composition comprises at least 1 ppb of the viscosifier, such asbetween 1 ppb and 10 ppb of the viscosifier.

The composition comprises at least 6 ppb of the hydrophobicnanomaterial, such as between 6 ppb and 20 ppb of the hydrophobicnanomaterial.

The composition includes an emulsifier.

The composition includes an alkalinity agent.

The composition includes a filtration control agent.

The composition includes a water-soluble salinity agent.

The composition includes a weighting agent, such as one or more ofbarite, hematite, and manganese tetroxide.

In an aspect, a method includes combining a viscosifier and ahydrophobic nanomaterial in an oil phase, the viscosifier including acarbon chain and a polar group disposed along the carbon chain, thehydrophobic nanomaterial having an average particle size of less than 1The hydrophobic material includes a silane or siloxane molecule having anonpolar chain disposed on a surface thereof. The method includesforming a composition including an emulsion of water in the oil phasehaving the viscosifier and the hydrophobic nanomaterial.

Embodiments can include one or more of the following features.

Forming the composition includes forming a network of the hydrophobicnanomaterial in the composition.

A sag factor of the composition is less than 0.53, such as between 0.50and 0.53.

The composition is substantially free of clay.

The composition is substantially free of low gravity solids having anaverage particle size of greater than 5 μm.

The viscosifier includes one or more of a fatty acid, a fatty amine, anda fatty ester.

The hydrophobic nanomaterial includes hydrophobic nanosilica. Thehydrophobic nanosilica includes nanoparticles of silica having ahydrophobic outer surface.

The silane or siloxane molecule includes hexadecylsilane.

The average particle size of the hydrophobic nanomaterial is less than500 nm, such as less than 100 nm, such as between 10 nm and 20 nm.

A yield point of the composition is greater than 10 lb/100 ft2, such as15 lb/100 ft2.

A plastic viscosity of the composition is less than or equal to 60 CP.

The composition comprises at least 1 ppb of the viscosifier, such asbetween 1 ppb and 10 ppb of the viscosifier.

The composition comprises at least 6 ppb of the hydrophobicnanomaterial, such as between 6 ppb and 20 ppb of the hydrophobicnanomaterial.

The method includes introducing an emulsifier into the oil phase.

The method includes introducing an alkalinity agent into the oil phase.

The method includes introducing a filtration control agent into the oilphase.

The method includes introducing a water-soluble salinity agent into theoil phase.

The method includes introducing a weighting agent into the oil phase,such as a weighting agent including one or more of barite, hematite, andmanganese tetroxide.

The approaches described here can have one or more of the followingadvantages. The clay-free, LGS-free invert emulsion drilling fluidscontaining a primary viscosifier and a hydrophobic nanomaterial asdescribed here are resistant to barite sag and thus less prone todrilling problems that can be caused by barite sag, such as mud-weightgradient, stuck-pipe, loss circulation, well-bore instability, andwell-control difficulties. These invert emulsion fluids are stable underhigh temperature and high pressure conditions. The inclusion of aprimary viscosifier and a hydrophobic nanomaterial in the invertemulsion drilling fluids described here increases the yield point of thefluids, thus increasing the equivalent circulating density of the fluid.However, the inclusion of a primary viscosifier and a hydrophobicnanomaterial in the invert emulsion drilling fluids described here doesnot result in any significant increase in plastic viscosity, thusenabling these drilling fluids to be used at a high rate of penetration,which in turn allows fast drilling and reduced rig time. The hydrophobicnanomaterials used in the invert emulsion drilling fluids described herecan be hydrophobic silica nanoparticles. Silica is listed in the PLONOR(Poses Little Or No Risk to the environment) list of additives that canbe used in the North Sea, and thus the invert emulsion drilling fluidshere are environmentally friendly and usable in a variety of geographiclocations.

Other features and advantages are apparent from the followingdescription and from the claims.

BRIEF DESCRIPTION OF DRAWINGS

FIGS. 1A and 1B are schematic diagrams of wells.

FIG. 2 is a diagram of an invert emulsion fluid.

FIG. 3 is a flow chart.

DETAILED DESCRIPTION

We describe here an approach to reducing barite sag in clay-free, lowgravity solids (LGS)-free invert emulsion drilling fluids. The invertemulsion drilling fluids described here contain a plastic viscosifierand a hydrophobic nanomaterial, such as hydrophobic nanosilica. Theplastic viscosifier and hydrophobic nanomaterial together reduce the sagfactor of the invert emulsion drilling fluid, thus making the drillingfluid resistant to barite sag. In addition, the presence of plasticviscosifier and hydrophobic nanomaterial in the invert emulsion drillingfluid can increase the yield point of the drilling fluid, furtherimproving the performance of the drilling fluid.

Referring to FIG. 1A, a well 100, such as an oil well or a natural gaswell, is filled with a clay-free, low gravity solids (LGS)-free invertemulsion drilling fluid 102 that contains a weighting agent, such asbarite 104, hematite, or manganese tetroxide, or a combination of two ormore of these weighting agents. An invert emulsion drilling fluid, suchas drilling fluid 102, is formed of an emulsion of water in a continuousbase phase of oil or a water-immiscible synthetic fluid. The oil orsynthetic fluid can be, for instance, diesel oil, mineral oil, olefins,paraffins, esters, or other material that are immiscible with water andsuitable for use in well 100. The volume ratio of oil to water in aninvert emulsion drilling fluid can range from about 50:50 to about 95:5,such as from about 70:30 to about 90:10, such as about 70:30, about80:20, about 90:10, or another ratio.

Invert emulsion drilling fluids are often used in wells in whichwater-based drilling fluids are inappropriate. For instance, invertemulsion drilling fluids can provide better lubrication performance thanwater-based drilling fluids. Invert emulsion drilling fluids canmaintain stability at higher temperature and higher pressure thanwater-based drilling fluids. Invert emulsion drilling fluids can be usedin wells that include features, such as certain types of clay, thatreact upon exposure to water-based drilling fluids. Invert emulsiondrilling fluids can provide better shale inhibition performance thanwater-based drilling fluids, for instance, when the water phase of theinvert emulsion drilling fluid is a salt brine.

In some invert emulsion drilling fluids, clays, such as organoclay ororgano-bentonite, are used as viscosifiers, increasing the viscosity ofthe drilling fluid and stabilizing the water-in-oil suspension. In someinvert emulsion drilling fluids, low gravity solids (LGS) are used asviscosifiers to increase the viscosity of the drilling fluid and tostabilize the emulsion. LGS materials are materials that have a lowerdensity than the weighting agent (such as barite) used to weight thedrilling fluid, such as a density of less than 4.20 grams per cubiccentimeter (g/cm³) (the density of barite). In some examples, LGSmaterials have a density of less than about 2.70 g/cm³, such as adensity of about 2.60 g/cm³. LGS materials can be small particles, suchas micron-sized particles, such as particles with an average size ofbetween about 5 micrometers (μm) and about 50 μm, such as 5 μm, 10 μm,20 μm, 30 μm, 40 μm, 50 μm, or another size. An example of an LGS issmall-scale calcium carbonate particles. Clay-free invert emulsiondrilling fluids having LGS as viscosifiers are generally more thermallystable, more resistant to high pressure, and more tolerant tocontamination, and exhibit lower downhole losses than invert emulsiondrilling fluids containing clay. In some LGS-containing invert emulsiondrilling fluids, additional LGS material must be added to new batches ofthese fluids to maintain or bolster the rheological and suspensionproperties of the fluid.

In invert emulsion drilling fluids that are free of both clay and LGS,such as drilling fluid 102, the emulsified water phase acts as theprimary emulsifier. However, the emulsified water phase is generallyunable to provide sufficient viscosity to the clay-free and LGS freedrilling fluid 102. As a result, the emulsion of the drilling fluid 102breaks down as the drilling fluid 102 ages, resulting in phaseseparation of the drilling fluid 102 into water and oil phases. Phaseseparation in turn causes the suspension characteristics of the drillingfluid 102 to be degraded. The barite 104 weighting material then becomesunable to remain suspended in the drilling fluid 102, and begins to fallout of suspension, accumulating in a mass 106 toward the bottom of thewell 100. This precipitation of barite 104 from suspension is referredto as barite sag. Barite sag can give rise to various problems duringoperation of the well 100, such as the creation of a mud-weightgradient, the occurrence of stuck-pipe, a loss of circulation, well-boreinstability, and well-control difficulties. Barite sag can also resultin damage to drilling formations, such as fractures, which can lead tomud losses.

To reduce barite sag in clay-free, LGS-free invert emulsion drillingfluids, other components can be added to the drilling fluid to increasethe viscosity and improve the suspension characteristics of the drillingfluid. Referring to FIG. 1B, a well 150, such as an oil well or anatural gas well, is filled with a clay-free, LGS-free invert emulsiondrilling fluid 152 that contains a weighting agent, such as barite 154.The drilling fluid 152 can have a composition as described supra for thedrilling fluid 102, and can further include a primary viscosifier 156and a hydrophobic nanomaterial 158. The primary viscosifier 156 and thehydrophobic nanomaterial 158, when present together in the drillingfluid 152, have a synergistic effect that both increases the viscosityof the drilling fluid 152 and stabilizes the water-in-oil emulsion ofthe drilling fluid 152. As a result, barite sag in the drilling fluid152 is reduced or eliminated.

The primary viscosifier 156 is a material that increases the viscosityand improves the suspension properties of the drilling fluid 152. Theprimary viscosifier 156 can be a primarily nonpolar molecule having anonpolar portion and a smaller polar portion. In some examples, theprimary viscosifier 156 can be a fatty acid, a fatty amine, a fattyester, or another molecule that includes a non-polar carbon chain orring having a polar group along the carbon chain, such as at an end ofthe carbon chain. The carbon chain can be linear or cyclical. By carbonchain, we mean a linear chain, a branched chain, or a cyclical chainhaving a backbone of carbon atoms, such as an alkane chain, an alkenechain, or an alkyne chain. In some examples, the primary viscosifier 156can be a liquid anionic acrylic co-polymer, a hydrophobic polyanioniccellulose, or a styrene butadiene copolymer latex. In a specificexample, the primary viscosifier 156 is a C 36 dimer fatty acid such asRhemod™ L (a BAROID® product, Halliburton, Houston, Tex.). Otherexamples of primary viscosifiers include BDF™-570 and BDF™-489 (BAROID®products, Halliburton).

The invert emulsion drilling fluid can include between about 1 poundsper barrel (ppb) and about 10 ppb of primary viscosifier, such as about1 ppb, about 2 ppb, about 3 ppb, about 4 ppb, about 5 ppb, about 6 ppb,about 7 ppb, about 8 ppb, about 9 ppb, about 10 ppb, or another amountof the primary viscosifier. The weight concentration of the primaryviscosifier in the invert emulsion drilling fluid can be generallysimilar to, such as of the same order of magnitude as, the same order ofmagnitude as the weight concentration of an emulsifier in the invertemulsion drilling fluid, an alkalinity agent in the invert emulsiondrilling fluid, a filtration control agent in the invert emulsiondrilling fluid, or other components.

Without being bound by theory, it is believed that the primaryviscosifier 156 may contribute to increased viscosity and improvedemulsion stability through the interaction of the nonpolar carbon chainwith the oil phase of the emulsion and the interaction of the polar endgroup with the water phase of the emulsion.

The hydrophobic nanomaterial 158 further increases the viscosity andimproves the suspension properties of the drilling fluid 152. Thehydrophobic nanomaterial 158 can be, for instance, nanoparticles,nanorods, nanotubes, or nanomaterials of other shapes. The averageparticle size of the hydrophobic nanomaterial 158 can be, for instance,less than 1 less than 500 nm, less than 400 nm, less than 300 nm, lessthan 200 nm, less than 100 nm, less than 50 nm, less than 20 nm, oranother size. The average particle size of the hydrophobic nanomaterial158 can be at least two times less than the average particle size of thebarite 154 weighting material, at least three times less, at least tentimes less, at least 50 times less, at least 100 times less, at least500 times less, at least 1000 times less, or another amount less thanthe average particle size of the barite 154.

The hydrophobic nanomaterial 158 has a surface that is hydrophobic andchemically inert with respect to the primary viscosifier and the othercomponents of the drilling fluid. In some cases, the surface and theinterior of the hydrophobic nanomaterial 158 have a generally consistentcomposition. In some cases, the surface of the hydrophobic nanomaterial158 is treated to have a different composition than the interior of thehydrophobic nanomaterial 158. For instance, the hydrophobic nanomaterial158 can be formed of a hydrophilic material that is treated to form ahydrophobic surface. In an example, the hydrophobic nanomaterial 158 canbe nanoparticles of silica treated with a silane or siloxane moleculehaving a nonpolar chain, such as hexadecylsilane, dimethyldichlorosilane, or another molecule, for instance, such that the silaneor siloxane molecule is attached to the exterior surface of thenanoparticles. In a specific example, the hydrophobic nanomaterial 158is AEROSIL® R816 or R104 hydrophobic nanosilica nanoparticles (EvonikCorporation, Parsippany, N.H.) with a particle size of about 10-20 nm(nanometers).

The invert emulsion drilling fluid can include between about 2 ppb andabout 20 ppb of the hydrophobic nanomaterial, such as about 2 ppb, about4 ppb, about 6 ppb, about 8 ppb, about 10 ppb, about 12 ppb, about 14ppb, about 16 ppb, about 18 ppb, about 20 ppb, or another amount of thehydrophobic nanomaterial. The weight concentration of the hydrophobicnanomaterial can be between about two times and about four times theweight concentration of the primary viscosifier, such as about twotimes, about three times, or about four times. The weight concentrationof the hydrophobic nanosilica in the invert emulsion drilling fluid canbe generally similar to, such as of the same order of magnitude as, theweight concentration of an emulsifier in the invert emulsion drillingfluid, an alkalinity agent in the invert emulsion drilling fluid, afiltration control agent in the invert emulsion drilling fluid, or othercomponents.

Without being bound by theory, it is believed that the hydrophobicnanomaterial 158 may encourage the formation and maintenance of thewater-in-oil emulsion of the drilling fluid 152 through the smallparticle size and large surface area of the hydrophobic nanomaterial158. Furthermore, it is also believed that the organic or hydrophobicmoiety of the silane or siloxane chain that imparts hydrophobicity tothe nanomaterial can help to stabilize the invert emulsion drillingfluids. For instance, referring to FIG. 2, in a diagram of the invertemulsion fluid, it is believed that the hydrophobic nanomaterial canform a network that incorporates the barite weighting material, thusstabilizing the invert emulsion fluid against settling of the barite.The network can have a continuous morphology throughout all or part ofthe invert emulsion fluid

The clay-free, LGS-free invert emulsion drilling fluid 152 can alsoinclude other components. For instance, the drilling fluid 152 caninclude an emulsifier, such as an oil soluble sulfonate emulsifier, toenhance the stability of the water-in-oil emulsion of the drilling fluid152. The drilling fluid 152 can include an alkalinity agent, such aslime, to control the pH of the drilling fluid 152. The drilling fluid152 can include a high-pressure, high-temperature (HPHT) filtrationcontrol agent to help reduce HPHT fluid loss. The drilling fluid 152 caninclude water-soluble compounds, including salts such as calciumchloride or sodium chloride, metal nitrites, metal nitrates, metalhydrates, or other materials that provide salinity to the water phase.For instance, a concentration of between about 10,000 ppm (parts permillion) and 350,000 ppm of calcium chloride can be used.

The suspension characteristics of a fluid can be characterized in termsof the sag factor, which is an indication of the degree to which heaviercomponents in the fluid sink toward the bottom of the fluid. In the caseof the drilling fluid 152, the sag factor is an indication of the extentto which barite sag has occurred. The sag factor is calculated based onthe specific gravity (SG) at the top and bottom of a sample of fluid:Sag Factor=SG_(bottom)/(SG_(bottom)+SG_(top))

A sag factor of greater than about 0.53 indicates that a fluid has thepotential to experience barite sag; a sag factor of less than or equalto about 0.53 is generally considered to have good suspensioncharacteristics.

The presence of a primary viscosifier and a hydrophobic nanomaterial ina clay-free, LGS-free invert emulsion drilling fluid improves thesuspension properties of the drilling fluid, reducing or eliminating theoccurrence of barite sag. For instance, a clay-free, LGS-free drillingfluid including both primary viscosifier and hydrophobic nanomaterialcan have a sag factor of less than 0.53, such as between about 0.50 andabout 0.53, such as about 0.50, 0.51, or 0.52.

The presence of a primary viscosifier and a hydrophobic nanomaterialimproves the rheological properties, such as the yield point, of aclay-free, LGS-free invert emulsion drilling fluid. The presence of bothprimary viscosifier and hydrophobic nanomaterial can increase the yieldpoint of a clay-free, LGS-free drilling fluid by at least about threetimes, such as by about three times, about four times, about five times,about six times, about seven times, about eight times, about nine times,about ten times, or by another amount as compared to a clay-free,LGS-free drilling fluid that does not have both primary viscosifier andhydrophobic nanosilica (e.g., a drilling fluid with neither primaryviscosifier nor hydrophobic nanosilica or a drilling fluid with only oneof primary viscosifier or hydrophobic nanosilica). For instance, aclay-free, LGS-free drilling fluid including both primary viscosifierand hydrophobic nanomaterial can have a yield point of least about 10pounds per 100 square feet (lb/100 ft²), such as about 10 lb/100 ft²,about 12 lb/100 ft², about 14 lb/100 ft², about 16 lb/100 ft², about 18lb/100 ft², about 20 lb/100 ft², or another value of the yield point. Adrilling fluid with a high yield point generally has a high equivalentcirculating density and can enable efficient cleaning of the well.Although the yield point of a clay-free, LGS-free invert emulsiondrilling fluid can be significantly increased by the presence of aprimary viscosifier and a hydrophobic nanomaterial, the effect of theprimary viscosifier and the hydrophobic nanomaterial on the plasticviscosity of the invert emulsion drilling fluid can be relativelysmaller. For instance, the plastic viscosity of a clay-free, LGS-freedrilling fluid including both primary viscosifier and hydrophobicnanomaterial can be within about 70% of the plastic viscosity of anequivalent drilling fluid without primary viscosifier or hydrophobicnanomaterial, such as within about 70%, within about 60%, within about50%, within about 40%, within about 30%, within about 25%, within about20%, within about 10%, or within another amount. For instance, aclay-free, LGS-free drilling fluid including both primary viscosifierand hydrophobic nanomaterial can have a plastic viscosity of at leastabout 25 centipoise (cP) or less than about 60 cP, such as a plasticviscosity of 25 cP, 28 cP, 30 cP, 33 cP, 35 cP, 38 cP, 40 cP, 43 cP, 45cP, 48 cP, 50 cP, 53 cP, 55 cP, 58 cP, 60 cP, or another value ofplastic viscosity. Maintaining a relatively low plastic viscosityenables the drilling fluid that includes primary viscosifier andhydrophobic nanomaterial to be used at a high rate of penetration,thereby allowing fast drilling and reduced rig time.

The rheological properties of a clay-free, LGS-free drilling fluidincluding both a primary viscosifier and a hydrophobic nanomaterial canbe stable against high pressure and high temperature conditions such asthose found in high pressure or high temperature drilling formations.For instance, the plastic viscosity and yield point of a clay-free,LGS-free drilling fluid including both a primary viscosifier and ahydrophobic nanomaterial can remain substantially constant in the faceof high temperature, such as temperatures of at least about 150° F. ortemperatures of at least about 250° F. In some examples, a clay-free,LGS-free drilling fluid including both a primary viscosifier and ahydrophobic nanomaterial can be used in environments with temperaturesup to about 450° F.

FIG. 3 depicts a general process for the formulation of clay-free,LGS-free invert emulsion drilling fluids including a primary viscosifierand a hydrophobic nanomaterial. Components of the drilling fluid aremixed into the oil phase of the drilling fluid (200). The componentsthat are mixed into the oil phase include the primary viscosifier andthe hydrophobic nanomaterial. Other components, such as one or more ofan emulsifier, an alkalinity agent such as lime, a filtration controlagent, a salinity agent such as calcium chloride or sodium chloride, anda weighting agent such as barite or manganese tetroxide, are also addedto the oil phase. Water is added to the mixed oil phase (202) and awater-in-oil emulsion is generated (204). For instance, the water can beadded slowly under constant stirring, agitation, or sonication toencourage the emulsification of the water. The water-in-oil emulsion isallowed to stabilize (206), following which the fluid can be injectedinto a well for drilling operations (208).

EXAMPLE Formulation and Characterization of Invert Emulsion Fluids

The rheological properties and suspension characteristics of clay-free,LGS-free invert emulsion drilling fluids were studied to determine theeffect of primary viscosifier and hydrophobic nanosilica on therheological properties and suspension characteristics of the fluids.

The yield point and plastic viscosity of the fluids were determinedusing a FANN® Model 35 viscometer (Fann Instrument Company, Houston,Tex.), which is a direct-indicating rheometer powered by an electricmotor. The rheometer includes two concentric cylinders: an innercylinder called a bob and an outer cylinder called a rotor sleeve. Foreach fluid tested, a fluid sample was placed in a thermostaticallycontrolled cup and the temperature of the fluid in the cup was adjustedto 120±2° F. The temperature-controlled fluid sample in the cup wasplaced in the annular space between the two concentric cylinders of therheometer. The rotor sleeve was driven at a constant rotationalvelocity, producing a torque on the bob. A torsion spring restrains themovement of the bob, and a dial attached to the bob indicates thedisplacement of the bob. The dial readings were measured at variousrotor speeds, including 3, 6, 100, 200, 300, and 600 revolutions perminute (rpm). The experiments were conducted in accordance with standardprocedures set forth in Recommended Practice 13B-2, Recommended Practicefor Field Testing of Oil-based Drilling Fluids, Fourth Edition, AmericanPetroleum Institute (API), Mar. 1, 2005.

The plastic viscosity (PV) of a fluid represents the viscosity of thefluid when rheological test results are extrapolated to infinite shearrate according to the Bingham-Plastic rheological model. The plasticviscosity of a fluid can be calculated using the 300 rpm and 600 rpmshear rate readings determined as described supra according to thefollowing equation:PV=(600 rpm reading)−(300 rpm reading)

The yield point (YP) of a fluid is defined as the value obtained fromthe Bingham-Plastic rheological model when the rheological test resultsare extrapolated to a shear rate of zero. The yield point of a fluid canbe determined according to the following equation:YP=(300 rpm reading)−PV.

The yield stress, or Tau zero, of a fluid is the stress that causes thefluid to flow or yield. The yield stress can be extrapolated fromrheological test results at shear rates of 3, 6, 100, 200, 300, and 600rpm by applying a least-squares fit or curve fit to the Herchel-Bulkleyrheological model. Alternatively, the yield stress can be estimated bycalculating the low-shear yield point (LSYP) according to the followingequation:LSYP=2*(3 rpm reading)−(6 rpm reading).

Suspension characteristics of each fluid were determined by measuringtop oil separation and by calculating the sag factor of the fluidfollowing static aging. Top oil separation was quantified as the volumeof base oil separated from the fluid after static aging, as drawn fromthe static aging cell with a syringe. The sag factor was determined bydrawing 10 mL aliquots of fluid from the top and bottom of the fluidafter static aging and measuring the weight of each aliquot on ananalytical balance. The equation for sag factor is given supra.

Fluid loss characteristics were determined on a 175 mL capacity HPHTfilter press cell following API 13B-2 recommendations.

Formulations of invert emulsion drilling fluids were prepared andcharacterized to demonstrate the effect of primary viscosifier orhydrophobic nanosilica on the suspension characteristics of the invertemulsion drilling fluid. These formulations included SAFRA (SafraCompany Limited, Saudi Arabia) as a base oil. The primary viscosifierused in these formulations was Rhemod™ L and the hydrophobicnanomaterial was AEROSIL® R104, which is a hydrophobic fumed nanosilicathat is formed by surface treating with an octamethylcyclotetrasiloxane.The physical properties of AEROSIL® R104 are given in Table 1. Withoutbeing bound by theory, it is believed that the high surface area andsmall size of the nanosilica plays a role in the improved suspensioncharacteristics of the invert emulsion fluids containing both primaryviscosifier and nanosilica. These formulations of invert emulsion fluidsalso included LE SUPERMUL™ (Halliburton), an emulsifier. Theformulations included lime, an alkalinity agent. The formulationsincluded ADAPTA® (Halliburton), a filtration control agent. Theformulations also included calcium chloride, barite, and water. Theseformulations of invert emulsion fluids had a density of 12 pounds pergallon (ppg), an oil-to-water ratio (OWR) of 70:30, and a water phasesalinity (WPS) of 250,000 ppm. The specific composition of eachformulation is given in Table 2.

TABLE 1 Properties of AEROSIL ® R104 hydrophobic fumed nanosilicaProperty and test method Value Specific surface area (BET) 150 ± 25Carbon content 1.0-2.0 Tamped density (ex plant) approx. 50 according toDIN EN ISO 787/11, August 1983 Moisture (ex plant) — 2 hours at 105° C.pH ≥4.0 in 4% dispersion SiO₂ content ≥99.8 based on ignited material

Four different formulations of invert emulsion drilling fluids wereprepared and characterized, the compositions of which are given in Table2. Comparative formulation 0 included neither a primary viscosifier norhydrophobic nanosilica. Comparative formulations 1 and 2 included eithera primary viscosifier or hydrophobic nanosilica, but not both.Formulation 3 included both a primary viscosifier and hydrophobicnanosilica.

Each invert emulsion drilling fluid formulation was prepared accordingto the following procedure. The components of the fluid were addedsequentially in the order listed in Table 2 and mixed in a stainlesssteel mixing cup on a five spindle multimixer model at 11500 rpm afterthe addition of each component for the amount of time indicated in thetables. The fluid was then hot rolled in an HPHT stainless steel cell ina hot rolling oven for 16 hours at 250° F. Following the hot rolling, aportion of the fluid was removed for measurement of rheologicalproperties as described supra. The remaining fluid was mixed on themultimixer for 5 minutes and placed into an HPHT stainless steel agingcell to be static aged for 24 hours at 250° F. Each static aged fluidwas characterized for rheological properties and suspensioncharacteristics.

TABLE 2 Formulation, rheological properties, and suspensioncharacteristics of clay-free, LGS-free invert emulsion drilling fluidscontaining neither primary viscosifier nor hydrophobic nanosilica(Comparative Formulation 0), primary viscosifier or hydrophobicnanosilica (Comparative Formulations 1 and 2), and both primaryviscosifier and hydrophobic nanosilica (Formulation 3). 12 ppg 70/30 OWRMixing Comparative Comparative Comparative time Formulation 0Formulation 1 Formulation 2 Formulation 3 SAFRA Oil, ppb (Base oil)147.9 150.3 148.84 148.84 LE SUPERMUL, ppb 2 10.00 10.00 10.00 10.00(emulsifier) LIME, ppb (alkalinity agent) 2 1.50 1.50 1.50 1.50 RHEMODL, ppb (viscosifier) 5 0.00 3.00 0.00 3.00 ADAPTA, ppb (filtration 52.00 2.00 2.00 2.00 control agent) AEROSIL ® Nanosilica R 104, 5 0.000.00 10.00 10.0 ppb (hydrophobic nanosilica) CaCl2, ppb 5 29.50 29.6029.30 29.30 Water, ppb 84.9 85.30 84.50 84.50 Barite, ppb 10 229.9 222.2224.74 221.74 (weighting agent) Fluid 0 static Fluid 1 static Fluid 2static Fluid 3 static aged for aged for aged for aged for 24 hours at 24hours at 24 hours at 24 hours at 250 F. 250 F. 250 F. 250 F. 600 rpmFluid was very 30 50 75 300 rpm thin after hot 17 26 43 200 rpm rolling.12 18 32 100 rpm Accurate 8 10 19  6 rpm rheology 2 2 4  3 rpmmeasurement 1.5 1.5 3 PV not feasible. 13 24 32 YP 4 2 11 GELS 10 sec 21.7 5 GELS 10 min 2 2 8 Sag factor N/A: 0.57 0.64 0.504 Barite bed Oilseparation 100 ml 85 ml 60 ml 0.2 cm

These results show that an invert emulsion fluid with either primaryviscosifier or hydrophobic nanosilica, but not both, has a sag factorthat is greater than 0.53, and thus neither the primary viscosifier northe hydrophobic nanosilica alone is capable of preventing barite sag inthe invert emulsion fluid. Neither primary viscosifier alone orhydrophobic nanosilica alone results in an improvement in the suspensioncharacteristics of the invert emulsion fluid, and neither componentalone can prevent the occurrence of barite sag in the invert emulsionfluid.

Comparative Formulation 0, with neither primary viscosifier norhydrophobic nanosilica, exhibited poor rheological characteristics. Thestatic aged fluid was very thin, preventing accurate rheologicalmeasurements from being obtained. In addition, a bed of bariteaccumulated at the bottom of the HPHT cell during static aging, and thusno sag factor could be measured.

The presence of both primary viscosifier and hydrophobic nanosilicatogether gives rise to a sag factor that is less than 0.53, indicatingthat the primary viscosifier and the hydrophobic nanosilica togetherhave a synergistic effect that can improve the suspensioncharacteristics of the invert emulsion fluid and can reduce or eliminatethe occurrence of barite sag in these invert emulsion drilling fluids.Top oil separation was also significantly reduced by the presence ofboth primary viscosifier and hydrophobic nanosilica, indicating that theemulsion of these fluids is stabilized by the presence of primaryviscosifier together with hydrophobic nanosilica. The static aging timeand temperature and the amount of primary viscosifier and hydrophobicnanosilica in the invert emulsion drilling fluid had little effect onthe suspension characteristics of the fluid.

The rheological properties of the invert emulsion fluids are alsoimproved by the presence of both primary viscosifier and hydrophobicnanosilica, but again, neither the primary viscosifier alone nor thehydrophobic nanosilica alone has a significant effect on the rheologicalproperties. The yield point of Formulation 3, which contained bothprimary viscosifier and hydrophobic nanosilica, was increased by atleast a factor of about 3 over the yield points of ComparativeFormulations 1 and 2.

The results shown in Table 2 indicate that the presence of both primaryviscosifier and hydrophobic nanosilica together can effectively reduceor minimize the occurrence of barite sag in a clay-free, LGS-free invertemulsion drilling fluid and furthermore can increase the yield point ofthe drilling fluid.

Further formulations of invert emulsion fluids were characterized todetermine the stability against static aging and hot rolling atdifferent temperatures of invert emulsion fluids having both primaryviscosifier and hydrophobic nanosilica. The base oil used in theseformulations of invert emulsion drilling fluids ESCAID™ 110 (ExxonMobil,Irving, Tex.), which is a hydrocarbon base oil including carbon chainsof length 11 (C11) to 14 (C14), including n-alkanes, iso-alkanes,cyclics, and less than about 2% aromatics. The primary viscosifier usedin these formulations was Rhemod™ L. The hydrophobic nanomaterial wasAEROSIL® R816, which is a hydrophobic fumed nanosilica that is formed bysurface treating AEROSIL® 200 hydrophilic fumed nanosilica with ahexadecylsilane. The physical properties of AEROSIL® R816 are given inTable 3. These formulations of invert emulsion fluids also included EZMUL® NT (Halliburton), an emulsifier. The formulations also includedlime, ADAPTA®, calcium chloride, water, and barite. These formulationsof invert emulsion drilling fluids had a density of 12 ppg, anoil-to-water ratio (OWR) of 70:30, and a water phase salinity of 250,000ppm. The specific composition of each formulation is given in Table 4.

TABLE 3 Properties of AEROSIL ® R816 hydrophobic fumed nanosilicaProperty and test method Value Specific surface area (BET) 190 ± 20 m²/gCarbon content 0.9-1.8 wt. % Tamped density (ex plant) approx. 60 g/Laccording to DIN EN ISO 787/11, August 1983 Moisture (ex plant) ≤1.0 wt.% 2 hours at 105° C. pH 4.0-5.5 in 4% dispersion SiO₂ content ≥99.8 wt.% based on ignited material

Formulations 4 and 5, the compositions of which are given in Table 4,were processed as described supra, with the exception of the staticaging and hot rolling temperatures. One sample of Formulation 4 wasstatic aged at 250° F. for 24 hours followed by hot rolling for 16 hoursat 250° F. A second sample of Formulation 4 was static aged at 150° F.for 120 hours followed by hot rolling for 16 hours at 250° F. to measurethe effect of a long, lower temperature static aging on the suspensioncharacteristics of the invert emulsion fluid. Formulation 5, whichincluded a higher concentration of both primary viscosifier andhydrophobic nanosilica than Formulation 4, was static aged at 300° F.for 24 hours followed by hot rolling at 300° F. for 16 hours to measurethe effect of exposure to high temperatures on the suspensioncharacteristics of the invert emulsion fluid. Each static aged fluid wascharacterized for rheological properties and suspension characteristics.

TABLE 4 Formulation, rheological properties, and suspensioncharacteristics of clay-free, LGS-free invert emulsion drilling fluidscontaining both a primary viscosifier and hydrophobic nanosilica. 12 ppg70/30 OWR Mixing Formulation no. time, min 4 5 ESCAID 110, bbl 150.84Fluid 4 Fluid 4 147.00 Fluid 5 (Base oil) was was was EZ MUL NT, ppb 210.00 static static 11.00 static (emulsifier) aged @ aged @ aged @ LIME,ppb 2 1.50 250° F. 150° F. 1.50 300° F. (alkalinity agent) 24 hrs 120hrs 24 hrs RHEMOD L, ppb 5 3.00 5.00 (viscosifier) ADAPTA, ppb 5 2.003.00 (filtration control agent) AEROSIL ® R 816, ppb 5 8.00 12.00(hydrophobic nanosilica) CaCl₂, ppb 29.30 29.30 Water, ppb 5 84.50 83.53Barite, ppb 10 221.74 214.96 (weighting agent) Hot rolled at 250° F.(Formulation 4) or 300° F. (Formulation 5), 16 hours Yield stress at 600rpm 75 73 83 88 Yield stress at 300 rpm 45 44 50 52 Yield stress at 200rpm 35 34 39 40 Yield stress at 100 rpm 22 20 26 28 Yield stress at 6rpm 5 6 7 6 Yield stress at 3 rpm 5 5 6 6 Plastic Viscosity 30 29 33 36Yield Point 15 15 17 16 Low-Shear Yield Point 5 4 5 6 GELS 10 sec 7 8 78 GELS 10 min 20 22 30 32 HTHP, ml/30 min 4.0 5 (250° F.) Sag factor0.50 0.5 0.52 Oil separation 0.2 cm 0.2 cm 0.5 cm/ 4 ml

These results show that the rheological properties and suspensioncharacteristics of invert emulsion fluids containing both primaryviscosifier and hydrophobic nanosilica are relatively independent oftemperature.

Other implementations are also within the scope of the following claims.

What is claimed is:
 1. A method comprising: combining a viscosifier and a hydrophobic nanomaterial in an oil phase, the viscosifier including a carbon chain and a polar group disposed along the carbon chain, the hydrophobic nanomaterial having an average particle size of less than about 1 μm, the hydrophobic nanomaterial including a silane or siloxane molecule having a nonpolar chain disposed on a surface thereof; and forming a composition including an emulsion of water in the oil phase having the viscosifier and the hydrophobic nanomaterial, wherein a weight concentration of the hydrophobic nanomaterial in the composition is between about two times and twenty times a weight concentration of the viscosifier in the composition, and a sag factor of the composition is less than 0.53.
 2. The method of claim 1, wherein forming the composition comprises forming a network of the hydrophobic nanomaterial in the composition.
 3. The method of claim 1, wherein the composition is substantially free of clay.
 4. The method of claim 1, wherein the composition is substantially free of low gravity solids having an average particle size of greater than 5 μm.
 5. The method of claim 1, wherein the viscosifier includes one or more of a fatty acid, a fatty amine, and a fatty ester.
 6. The method of claim 1, wherein the hydrophobic nanomaterial includes hydrophobic nanosilica.
 7. The method of claim 6, wherein the hydrophobic nanosilica includes nanoparticles of silica having a hydrophobic outer surface.
 8. The method of claim 1, wherein the silane or siloxane molecule includes hexadecylsilane.
 9. The method of claim 1, wherein the average particle size of the hydrophobic nanomaterial is less than 100 nm.
 10. The method of claim 1, wherein a yield point of the composition is greater than 10 lb/100 ft².
 11. The method of claim 1, wherein a plastic viscosity of the composition is less than or equal to 60 CP.
 12. The method of claim 1, wherein the composition comprises at least 1 ppb of the viscosifier.
 13. The method of claim 1, wherein the composition comprises at least 6 ppb of the hydrophobic nanomaterial.
 14. The method of claim 1, comprising introducing one or more of an emulsifier, an alkalinity agent, a filtration control agent, and a water-soluble salinity agent into the oil phase.
 15. The method of claim 1, comprising introducing a weighting agent into the oil phase.
 16. The method of claim 15, wherein the weighting agent comprises one or more of barite, hematite, and manganese tetroxide.
 17. The method of claim 1, wherein a weight concentration of the hydrophobic nanomaterial in the composition is between about two times and twenty times a weight concentration of the viscosifier in the composition.
 18. The method of claim 17, wherein the weight concentration of the hydrophobic nanomaterial in the composition is between about two times and ten times the weight concentration of the viscosifier in the composition.
 19. The method of claim 18, wherein the weight concentration of the hydrophobic nanomaterial in the composition is between about two times and about four times the weight concentration of the viscosifier in the composition. 